Much of our current energy needs are met through use of hydrocarbons, such as oil, natural gas, and condensates, which are recovered from naturally occurring deposits or reservoirs. Typically, such hydrocarbons are in a liquid or gas phase in the reservoir. Liquid hydrocarbons are often produced by pumping them from the reservoir to storage tanks or a flow line connected to the wellhead. The pumping or "lifting" costs include capital costs, such as the pump, the prime mover (i.e., motor), the rods and the tubing, and operating costs, such as labour, royalties, taxes, and electricity. Because some of these costs are fixed, a certain production rate is required to make such recovery economically feasible If the revenue generated by selling the recovered hydrocarbons is less than the lifting costs to so recover them, then the well may be temporarily closed up or permanently shut in. In some cases wells may be reopened when new technology becomes available, and in other cases the well may be reopened if energy prices rise, once again making production and recovery economically attractive. Alternatively, a permanently shut-in well would be plugged with concrete and abandoned altogether.
Typically, an oil well will be shut in or abandoned when only 20-50 percent of the total oil in the reservoir is recovered, because it becomes uneconomic to continue to operate the well. This unrecovered oil has been recognized as a lost resource in the past and thus there have been many techniques proposed to stimulate production rates and consequently increase the ultimate recovery of oil from reservoirs.
There are a number of reasons why oil and gas well productivity may decline over time. For example, productivity declines if 1) there is insufficient pressure differential between the well and the reservoir, 2) the flow between the reservoir and the well is obstructed, or 3) the mobility of the oil is restricted due to relative permeability effects Conventional production practice, such as waterflooding, gas re-injection and the like, is effective for maintaining reservoir pressure to overcome the first problem. Many different phenomena can result in impediments to the flow of fluid hydrocarbon from the reservoir to the wellbore. For example, there may be precipitation of mineral scales, such as calcite, anhydrite or the like, in the formation, the perforation tunnels (located at the bottom of the well) or the wellbore. There may be mobile inorganic fines, such as clay or sand, which are carried by the flow of the fluid being recovered into narrow pore throats thereby blocking them. There may be clay minerals which swell under the influence of recovery and which therefore result in flow path restrictions and a flow reduction. There may be an alteration of the saturation of a particular phase of the well. For example, in a low permeability reservoir with a very low water content, damage can be caused if water contacts the reservoir. The damage occurs as a reduction in the relative permeability (i.e., mobility) of the oil phase.
It is believed that one of the major flow obstructions which results in declining productivity is the accumulation in the reservoir at or adjacent to the well of solid phase wax. This wax may be due to either an accumulation of mobile waxy solids with subsequent plugging or narrowing of the pore throats in the reservoir rock or precipitation of solid wax due to temperature, pressure or composition changes in the hydrocarbons being recovered. Such changes might occur at any point between the reservoir and the storage tanks on the surface. Moreover, because the wax is associated with the oil phase, any accumulation of solid phase wax in the well tends to selectively damage the mobility of the oil phase and thus reduce the production of oil from the well.
Many methods have been developed and proposed to stimulate the production of oil in wells to increase profitability and extend the ultimate recovery. One common and relatively successful technique is referred to as hydraulic fracture. In this technique, a high pressure fluid is used to fracture the rock formation, thus creating a channel which penetrates into the reservoir. The fracture is subsequently propped open using a granular material, such as sand. The fracture bypasses hydraulic restrictions to the inflow of oil into the well by creating a new open channel and also by exposing a large surface area of the reservoir rock to the channel, thereby greatly increasing productivity of the formation surrounding the bottom of the well. However, this technique is subject to failure if the proppant is not successfully carried into the new fractures made in rock formation. Further, it can be difficult to control the fracturing process and if the fracture accidentally is extended beyond the oil zone into a gas or water zone, then the well may become uneconomic to operate.
Hydraulic fracturing can temporarily improve the productivity of wells which have a productivity decline due to an accumulation of solid wax. However, such technique does not remove the existing wax damage or change the basic wax damage mechanism; it merely bypasses existing wax damage. Thus, productivity of a fractured well will often decline at a high rate due to the accumulation of wax damage in the fracture channel Subsequent refracturing of the reservoir may provide an improvement in productivity, but again productivity will decline over time. Subsequent refracturing thereafter typically does not provide sufficient productivity increases to be economic. Such fracturing may thus provide a short-term method of increasing production from a well, but because it does not address the wax accumulation problem, the problem usually re-asserts itself, resulting eventually in a loss of effectiveness for the fracturing method.
Other treatments to stimulate wells include perforating the casing of the well with shaped charges to provide channels or perforation tunnels through which the fluids can flow. Again this technique provides a short term improvement which may bypass, but does not remove, accumulations of wax, nor, prevent the further accumulation of wax.
Matrix acidization, in which an acid is pumped into a reservoir to dissolve formation rock and precipitated scales can also stimulate production in wells. However, for wells having solid wax damage, matrix acidization may not work effectively, as solid wax is insoluble in acid. Because acidization is inherently prone to create channels along the path of "least resistance", the acid often bypasses the low permeability wax damaged oil zone and instead penetrates directly into a water zone at the bottom of the reservoir. Thus wax deposits can limit the success of acidization stimulation, even preventing effective removal of any dissolvable rock or precipitation which are wax coated.
Another technique for stimulating production is thermal stimulation. In the case of thermal stimulation, oil, water or steam heated above grade may be pumped to the bottom of the well to try to stimulate production from the recovery area. However, it has been found very difficult to transfer the heat by steam, water or oil to the bottom of the well by reason of the thermal losses which take place as the hot medium is being transported down the well bore. (Society of Petroleum Engineers, Paper No. CIM/SPE 90-57 OPTIMIZING HOT OILING/WATERING JOBS TO MINIMIZE FORMATION DAMAGE by John Nenniger and Gina Nenniger of Nenniger Engineering Inc.)
For example, in the "hot oiling" technique, crude oil, solvent or water is heated above grade to a typical temperature of 100.degree.-125.degree. C. and then pumped into the well. Usually the heated fluid is pumped into the annulus between the tubing and the casing. Depending on the particular situation, some fluid will accumulate in the annulus, some fluid will flow into the reservoir, and some fluid will flow back up the tubing and out of the well. Heat from the "hot oil" is lost through the casing to the rock surrounding the well. Heat is also lost in counter-current heat exchange with the fluid which circulates upwards out of the tubing. Temperature measurements at the bottom of the well show that the bottom hole temperature drops during the treatment and excessive volumes of hot fluid do not significantly raise the bottom hole temperature. Typically, the heated fluid will lose its excess temperature in the top 300-400 m section of the well due to heat losses to the casing and the counter-current heat exchange described above. Due to the geothermal gradient, by the time the "hot fluid" reaches the production zone at bottom of the well, it is likely cooler than the casing and thus actually absorbs heat from the casing and the rock surrounding the well. Thus for most applications (for wells deeper than 300 m), the "hot fluid" arrives at the bottom of the well at a temperature below the reservoir temperature. Because the bottom hole temperature decreases during treatment, waxy solids are likely to precipitate from the crude oil and be filtered out in the pores of the reservoir in the recovery zone as the fluid flows into the recovery zone. Thus, although the "hot oil" technique removes the wax deposits near the wellhead, it often causes an accumulation of the waxy solids in the perforation tunnels and reservoir surrounding the well. Thus, the application of heat to the well by pumping "hot oil" into the well through the annulus is inadequate to remove waxy deposits in the formation and in fact usually leads to even greater formation damage. The hot watering technique experiences comparable heat losses and causes additional formation damage (e.g., by increasing the water saturation around the well, precipitation of inorganic scales, etc.), so hot watering is not an effective technique for removing formation damage due to wax.
Another method of thermal stimulation is disclosed in Canadian Patent 1,182,392, dated Feb. 12, 1985 in the name of Richardson et al. (see also U.S. Pat. No. 4,219,083) which discloses a nitrogen gas generation system to produce a heat spike in a water-based brine solution. In this method, the salt water solution undergoes a chemical reaction to release heat, together with nitrogen gas, as it is being delivered down the well, thereby avoiding some of the heat losses associated with transporting a hot fluid down the well as discussed above for the "hot oil" technique; the salt water solution only becomes hot when it is some way down the well. The salt water solution may then be shut in for a period of about 24 hours to allow the heat carried by the solution to melt wax located in the recovery zone. The disclosure notes that wax solvents may be flushed down the well prior to or after the injection of the heat-producing salt water solution.
However, there are several inherent disadvantages to the method disclosed in patent 1,182,392. Firstly, the wax is not soluble in the salt water solution, so even if the heat developed is sufficient to melt the solid wax deposits, two separate liquid phases will occur (i.e. a liquid hydrocarbon phase including liquid wax and crude oil and a liquid aqueous phase including formation water and salt water solution). If the water saturation is high in order to get a significant temperature rise then the relative permeability of the liquid hydrocarbon phase will be very low as compared to the water and the mobility of the hydrocarbon phase containing the wax will be obstructed. Thus, the water-based fluid cannot effectively carry the melted wax out of the reservoir. Even if solvent is present in the formation, either by means of a pre-treatment flush, or a post-treatment flush, the salt water solution and nitrogen gas produced by the reaction will together greatly impede the solvent from coming into contact with any such melted wax, greatly reducing the treatment's effectiveness.
Past studies have shown the effect of water saturation on relative permeability (B. C. Craft and M. F. Hawkins Applied Reservoir Engineering, Prentice-Hall, 1959). The relative permeability curves (i.e. data) for a particular reservoir allow the flow rate of oil or water through rock pores to be calculated as a function of fluid saturation and pressure drop. For example, on page 357 FIG. 7.1 shows that if the water saturation exceeds 0.85, then the remaining 0.15 volume fraction of oil will not be mobile. FIG. 7.2 of this reference also shows that an increase in the water saturation of just 0.35 decreases the relative permeability (or mobility) of the oil phase by 100 fold. Thus, if salt water solution is squeezed into the formation, the saturation of the water is increased and the relative permeability of the oil/melted wax phase will be greatly reduced. If the water saturated formation is subsequently contacted with a solvent, the solvent will tend to channel due to the relationship between relative permeability and fluid saturation described above. Thus, the solvent cannot effectively contact or mobilize the melted wax. Thus, contacting the formation with an aqueous based heating fluid to be followed by a solvent is unlikely to effectively remove the wax from the pores of the reservoir rock. Furthermore, water can be damaging to some reservoirs as it can cause clay swelling or fines mobilization.
What is desired therefore is a method for removing the accumulations of solid wax from the fluid passageways which comprise the well to remove impediments to the flow of liquid hydrocarbons being produced from the reservoir to enable increased liquid hydrocarbon production rates. Preferably, such a method would be inexpensive to use and would be capable of being used without a great deal of inconvenience or alteration to the well itself. Preferably, the treatment would physically remove any solid wax, and would be effective every time it was used. The method also would preferably not introduce any water--based liquids into the formation to avoid reducing relative permeability, and hence mobility of the liquid hydrocarbons. Such method would also avoid heat losses associated with transporting a fluid from a cold location (i.e., the wellhead) to a warmer zone (i.e., the downhole production zone), which could lead to a decrease in the bottomhole temperature and cause wax precipitation and accumulation, resulting in formation damage.